The production of hydrocarbons from underground reservoirs is often hampered by a damaged zone in the reservoir rock around the well bore.
These damage mechanisms include:
1. Drilling damage caused by the high velocity of drilling fluids passing through the jets in the drilling bit which can force liquid and particulate matter beyond the well bore out into the reservoir pore spaces.
2. Plugging of the pore spaces in the reservoir region immediately around the drilled well bore can be caused by formation rock material from the drilling process. These drill cuttings and fines can be forced into the pore spaces of the surrounding rock by several mechanisms; the rotation of the drill string and the weight of that drill string can put very high forces on particulate matter trapped between the drill string and the face of the well bore, compacting it into the pore spaces of the formation; or the pressure of the fluid in the well bore, which is normally higher than the pressure in the surrounding reservoir, can force drilling fines beyond the compaction zone and into the surrounding pores
3. Plugging of the pore spaces around the well bore can also be the result of particulate matter added to the drilling fluids to create a filter cake around the well bore which is intended to minimize the leak off of liquids into the surrounding reservoir. The mechanisms that force this particulate matter into the pore spaces are identical to those that cause damage from drilling fines, notably pressure, force and velocity.
4. Pore space reduction can occur as a result of alteration to the reservoir materials in the region surrounding the well bore. The most well known damage of this type is caused by clays in the reservoir which absorb fluids, most often water, and swell in physical size. This swelling reduces the size of the pore spaces and often reduces the permeability to the flow of reservoir hydrocarbons. This type of damage is often very difficult to remove or alter, and usually requires a hydraulic fracture with compatible fluids to bypass the damaged zone.
5. Fluid blockage in the region around the well bore results when the naturally occurring fluids in the reservoir are replaced by fluids injected during drilling or well service operations. Drilling fluids, fresh water, salt water, acids, acid reaction products, and other chemicals that are used in well operations can result in fluid blockage. These fluids can alter the surface tension between the rock and the fluid, which can have a dramatic impact on fluid mobility and production. Emulsions and colloidal suspensions are two specific types of fluid blockage.
The development of horizontal drilling technology has provided additional challenges with respect to formation damage. In vertical wells, it normally only takes a matter of hours to drill through a hydrocarbon bearing formation and establish a stable filter cake on the face of the well bore to prevent further damage due to migration of solids and fluids. In horizontal wells however, drilling of the producing formation can take several days or longer which means that the formation is exposed to drill cuttings, drilling fluids and pressure for a much longer period of time than a conventional vertical well. The filter cake which helps to prevent fluid loss and invasion of particulate matter into the formation is much more susceptible to being removed by the weight, rotation and axial movement of the drill pipe tool joints. This can lead to a damaged region around the well bore which is much larger in areal extent and is more severely damaged than is the case for a vertical well bore.
In practice, damage removal in producing hydrocarbon reservoirs has been achieved through the use of primarily two techniques, acidizing and hydraulic fracturing. In carbonate reservoirs, acid injection to dissolve some of the rock material has proven to be effective in many situations. It is generally only when the damage is so severe as to prevent any injection of acid into the formation, that acid does not reduce the damage and improve production.
The use of acid to remove damage in reservoirs which have an active water drive can result in very serious production problems if the acid opens up channels into the water bearing portion of the reservoir. This situation can lead to very high water production levels which may render the well uneconomic to produce.
In sandstone reservoirs, acid is much less effective in reducing damage, particularly if the damaged region around the well bore is relatively deep or if the damage is severe. It is common practice in sandstone reservoirs to use hydraulic fracturing to create a fracture in the formation which extends beyond the region of damage and provides a flow channel from the undamaged formation to the well bore.
Virtually all well stimulation methods are based upon providing a pressure surge in the well bore or in the formation. One of the first methods utilized for oil well stimulation involved dropping containers of nitro-glycerin down wells, which caused a high pressure surge when the nitro-glycerin exploded. Even acidizing and fracturing operations on wells can be classified as surge techniques since they employ the use of positive pressure across the well bore to formation interface. Numerous other surge techniques have been developed over the years including, underbalanced perforating systems, overbalanced explosive “Stress-Frac” type systems, drop bar surge completion techniques, and more recently, extreme overbalanced perforating systems.
Some of these techniques use a long pressure cycle and some of them use an extremely short pressure cycle of less than a second. They generally use either a positive or a negative pressure differential across the well bore to formation interface, but not both. The pressure surge initiation can be either at surface or down hole in close proximity to the formation face. These techniques can involve the injection of solids (fracturing), liquids (acidizing) or gases (perforating) across the well bore formation interface.
It is common in the industry during stimulation operations that involve pumping fluid into the formation, to use a tubing string to convey the treating fluids to the well bore adjacent to the formation. This provides more control over displacement of the fluids, allows higher treating pressures and allows packers and other down hole flow control devices to be utilized. The tubing can be either jointed tubing or continuous coiled tubing.
It is also common in the industry to utilize sealing elements such as packers to isolate a segment of the well bore which can be “selectively” stimulated, without stimulating the remainder of the well bore. A single sealing element can be used to divide the well bore into two regions, the first region being below the sealing element and the second region being above the sealing element. Two sealing elements can be utilized to isolate a smaller region of the well bore from the regions below the lower packer and above the upper packer. Down hole devices such as fluid control valves, circulating valves and packer inflation valves which function either by mechanical or hydraulic means are well known in the industry.
In horizontal wells with long open hole sections of up to several thousands of feet, it can be appreciated that without selective stimulation tools, all treating fluids will follow the path of least resistance or least formation damage. As a result, it is possible for all of the stimulation fluids to enter the formation at the same point, and that no stimulation of the remaining formation will occur. Both gross stimulation techniques and selective stimulation techniques for treatment of horizontal wells are commonly practised.
U.S. Pat. No. 4,898,236 and Canadian patent No. 1,249,772 to Sask discloses a drill stem testing system which includes inflatable packers to isolate well bore regions for evaluation. Sask also discloses electrically operable valves for allowing fluids to flow between the various regions within and surrounding the down hole drill stem testing apparatus. However, it should be noted that Sask discloses the use of two position electrically operable valves which are biassed to one position, which necessitates the use of multiple electrically operable valves to accomplish the tasks required for drill stem testing operations.
Sask also discloses the use of an electrically operable pump for withdrawing fluids from the well bore and providing those fluids under pressure to expand inflatable type packers.
In a long horizontal well bore there is often a significant amount of particulate matter which in a vertical well would fall to the bottom of the well bore. Any packer inflation means utilizing well bore fluids for expanding packers in a horizontal well has the inherent risk of plugging either the pump or the packers with well bore particulate materials, particularly where the packers must be expanded a number of times to selectively evaluate or stimulate discreet segments of the well bore.